For certain production wells, artificial lift systems can become necessary when the natural pressure within the underground reservoir is no longer adequate to naturally push produced fluids to the surface. Electric submersible pumps (ESPs) are often used in these situations. Electric power is transmitted from the surface via an umbilical power cable to the downhole ESP. Conventionally, ESPs were deployed at the end of production tubing, with the power cable installed outside the production tubing. However, electrical failures were often associated with this type of setup, and anytime there was an electrical failure, a rig had to be brought in to pull out the production tubing and the ESP.
In an effort to overcome this problem, alternative ESP systems were developed. One such system is a power cable deployed ESP system. In this system, the power cable is used to transmit power, as well as to support the ESP itself. In this alternate setup, both the power cable and the ESP are installed inside the production tubing.
In order to improve overall safety for a power cable deployed ESP system, well control can employ a deep set surface controlled subsurface safety valve (SCSSV). The SCSSV is installed in the production tubing below the ESP. The SCSSV is designed to be fail-safe, so that the wellbore is isolated in the event of any system failure or damage to the surface production-control facilities. An example of a prior art setup is shown in FIG. 1.
In FIG. 1, production tubing 40 is disposed within casing 20. ESP 90 is supported by power cable 100, as well as production tubing 40 via isolation member 120. Casing 20 has perforations 22 in a producing region 30 of an underground reservoir. Produced fluids enter casing 20 through perforations 22. The produced fluids then travel through the safety valve 80 into an inner volume 105 of production tubing 40, and flow through a narrow gap between ESP 90 and production tubing 40. The produced fluid then enters ESP 90 via intake slots 97, travels through medial pump body portion 98, and exits ESP 90 above isolation member 120 via discharge slots 111. The produced fluid is now back within production tubing 40 (at a point above isolation member 120), where it can be pumped to the surface. Lower packer 50 prevents produced fluids from traveling up the annular region formed between production tubing 40 and casing 20.
In these types of setups, the fluid velocity of the production fluids can get quite high due to the narrow gap between the production tubing and the ESP. In typical installations, the narrow gap can range from 0.079 inch to 0.225 inch, depending on the size of the production tubing and chosen ESP. For a typical target rate of 6,000 barrels per day (bpd) production using production tubing of 4½ inch, the fluid velocity of the produced fluid coming through this gap can be 70 ft/s. For 5½ inch tubing, the velocity can still reach 40 ft/s. However, at fluid velocities in this range, the ESP system can fail quickly due to erosion. Additionally, at high velocities such as these, the frictional losses are quite significant. Overcoming frictional losses is usually achieved using longer motors and longer pumps; however, doing this increases the capital costs. Additionally, longer equipment increases installation difficulties, particularly for live well deployment with a surface lubricator. As such, ESP systems are typically only operated at 1,000 to 2,000 bpd.
Therefore, it would be advantageous to provide an ESP system that did not suffer from erosion or high friction losses at production rates higher than 2,000 bpd.